Field of the Invention
The present invention relates to a method of monitoring the quality of surface seismic data processing and to a method of processing vertical seismic profile data.
Surface seismic exploration can be performed in a 2D or a 3D mode. The 2D mode is simpler to describe. FIG. 1 of the accompanying drawings is a schematic illustration of a simple 2D land based seismic survey arrangement, although a similar surveying process can also be carried out at sea. Only two sources and two receivers will be considered for simplicity. The two sources S.sub.1 and S.sub.2 are regularly spaced in an array to one side of an origin O. The two receivers R.sub.1 and R.sub.2 are also regularly spaced in an array on the other side of the origin O. The sources and receivers are arranged such that the origin is the midpoint M.sub.1 of a first source and receiver pair formed by S.sub.1 and R.sub.1, and also the midpoint M.sub.2 of a second source and receiver pair formed by S.sub.2 and R.sub.2. The distance between a source and a receiver is known as an "offset".
If a reflector 2 beneath the survey arrangement of FIG. 1 is horizontal, then seismic energy emitted by the first source S.sub.1 will be received by the first receiver R.sub.1, whereas seismic energy emitted by the second source S.sub.2 will be received by the second receiver R.sub.2. In FIG. 1, the midpoints of the two described source receiver pairs are at the origin O, and the reflections occur directly below the midpoints M.sub.1 and M.sub.2.
In practice, the seismic energy sources are actuated in turn, and each receiver receives reflected signals. The traces of received signals are then assigned to a position which is the midpoint between the respective receiver and the source that was actuated.
The presence of non-horizontal reflectors, known as dipping reflectors, changes the situation, as shown in FIG. 2 of the accompanying drawings. The same pairs of sources S.sub.1, S.sub.2 and receivers R.sub.1, R.sub.2 do not now have a common reflection point on the dipping reflector, neither of the reflection points being at the actual midpoint M between the sources and receivers. During a processing sequence described hereinafter, the object of a migration step is to determine the location of the actual reflection points, which, before migration, are assumed to have occurred below the midpoint M as would occur with a horizontal reflector.
This problem has been accounted for in the steps developed to process surface seismic data. The processing of surface seismic data generally includes a number of steps, each of which is intended to improve the data quality. The processing often includes the steps of:
1) Designature--The shape of the input energy signature is extracted from the seismic data and is then converted to one of a known property which allows improved data processing performance within the subsequent steps; PA1 2) Gather--The seismic data are recorded such that energy reflecting (or apparently reflecting) from the same point on a sub-surface is grouped together. These are commonly called common mid points CMP or common depth points CDP; PA1 3) Velocity analysis--The data within the CMPs contain information from varying source receiver offsets. The time at which reflection from a given point on a reflecting surface will be recorded varies with source receiver offset and sub-surface velocity. The varying time delay as a function of offset is exploited in order to determine the subsurface velocity profile; PA1 4) Deconvolution--Energy propagating from a source to a receiver may undergo multiple reflections in addition to single "primary" reflectors. These spurious multiple reflections are attenuated by the deconvolution step. The deconvolution process can compress the time series wavelet which represents reflection at any given reflector and as such is an aid to increasing resolution of closely spaced reflectors. PA1 5) Stack--The velocity profile derived at step 3 is used to correct the recorded offset data to simulate data recorded at zero offset. The corrected traces are then added together to enhance a "primary" signal at the expense of ill corrected or non-primary energy. PA1 6) Migration--The gather and stack processing steps assumed that the reflectors are horizontal. This results in errors as indicated with respect to FIG. 2. The migration step moves any non-horizontal reflectors to their correct spatial position and also focuses the seismic image; PA1 7) Filtering--To remove frequencies not considered as primary reflection energy.
Each process changes the data. It would be desirable to monitor how each process step affects a reflectivity sequence and embedded wavelet contained within the surface seismic data.
Surface seismic acquisition is not the only way to obtain seismic data. Data may also be obtained by drilling a borehole and placing an array of receivers on the ground surface and a seismic source in the borehole, or by placing a seismic source on the surface, and an array of receivers at various depths down the borehole. The latter option is the more common arrangement. The resulting data are known as a borehole vertical seismic profile.
A simplified arrangement is schematically illustrated in FIG. 3 of the accompanying drawings. A seismic energy source S.sub.b is located at the top of a borehole 6 (represented by a dotted line in FIG. 3). Geophones G.sub.1 to G.sub.8 are located in a regular linear array at different depths within the borehole.
Seismic energy resulting from actuation of the source can travel directly towards each of the geophones and the delay between actuation of the source and arrival of the seismic energy can be used to derive a velocity profile for seismic energy within the rocks through which the borehole passes. This directly received seismic signal is not illustrated in FIG. 3. However, as illustrated, seismic energy reflected directly from reflectors deeper than the geophones can be recorded. Seismic energy paths for geophones G.sub.1, G.sub.4 and G.sub.8 have been illustrated. Some of the paths have been slightly displaced with respect to one another to improve the clarity of the diagram.
A first path 8 represents energy that travels to the first reflector 2 and is reflected to the first geophone G.sub.1. A second path 10 represents energy that travels to the second reflector 4 and is reflected to the geophone G.sub.1. A third path 12 represents energy that travels to the first reflector 2 and is reflected to the geophone G.sub.4 just above the first reflector 2. A fourth path 14 represents energy that is reflected from the second reflector 4 to the geophone G.sub.4. A fifth path 16 represents energy that is reflected from the second reflector 4 to the geophone G.sub.8 located just above the second reflector 4. The presence of a dipping reflector 4 enables energy reflected from points positioned away from the path of the borehole to be received by geophones located higher up in the borehole than the reflector 4.
FIG. 4 of the accompanying drawings schematically illustrates the seismic record or trace recorded by each of the geophones G.sub.1 to G.sub.8. Only reflection signals are shown. Direct arrival signals have been omitted for clarity although, in order to generate a plot of the type shown in FIG. 4, the direct arrival time from the source to a respective geophone is added to the recorded reflection time by statically shifting each trace downwards by an amount equal to its own direct arrival time. In the absence of dip, such a time shifting causes upward reflections to line up at their correct reflection times below the surface. Thus, the first signals in the traces of geophones G.sub.1 to G.sub.4 resulting from reflection at the first reflector 2 become aligned in time. The diagonal line 20 represents the two way travel time from the source to each geophone. The origin in depth of a reflection event is precisely identified when the reflection event is coincident with the line 20. Thus the first reflection in the trace for G.sub.4 and the second reflection in the trace for G.sub.8 can be identified as coming from reflectors whose depths correspond to the positions of G.sub.4 and G.sub.8 within the borehole.
The reflections at the second dipping reflector 4 do not line up in travel time but follow a hyperbolic curve. However, the time of the reflection signal on the trace for the geophone G.sub.8 corresponds to the migrated time for the corresponding reflection event in the surface seismic data. The second reflection event on the trace for G.sub.1 corresponds to the zero offset unmigrated surface seismic data. This is because, when the geophone and source are nearly coincident at the surface, the trace recorded is identical to the recorded zero offset surface seismic trace i.e. before migration. Thus, the position in time of the second reflection on the trace for geophone G.sub.1 is the same as the unmigrated surface seismic time, and the position in time of the second reflection on the trace for the geophone G.sub.8 is the same as the migrated surface seismic time.
Similarly, for the first reflector, the reflection event is correctly placed in time for trace G.sub.1 relative to the unmigrated surface seismic data, and correctly placed in time for trace G.sub.4 relative to the migrated surface seismic data. Since the first reflector is flat, the migrated and unmigrated times are the same. In the presence of dip, the unmigrated time is less than the migrated time.
It is known to compare borehole vertical seismic profile data with surface seismic data. However, except in the absence of dip, such a comparison cannot be made until after the surface seismic data have been migrated to a position equivalent to that of the borehole.